1. Field of the Invention
The present invention generally relates to methods and apparatus for use in oil and gas wellbores. More particularly, the invention relates to methods and apparatus for communicating between surface equipment and downhole equipment.
2. Description of the Related Art
Oil and gas wells typically begin by drilling a borehole in the earth to some predetermined depth adjacent a hydrocarbon-bearing formation. Drilling is accomplished utilizing a drill bit which is mounted on the end of a drill support member, commonly known as a drill string. The drill string is often rotated by a top drive or a rotary table on a surface platform or rig. Alternatively, the drill bit may be rotated by a downhole motor mounted at a lower end of the drill string. After drilling to a predetermined depth, the drill string and drill bit are removed and a section of the casing is lowered into the wellbore. An annular area is formed between the string of casing and the formation, and a cementing operation is then conducted to fill the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
It is common to employ more than one string of casing in a wellbore. Typically, the well is drilled to a first designated depth with a drill bit on a drill string. The drill string is then removed, and a first string of casing or conductor pipe is run into the wellbore and set in the drilled out portion of the wellbore. Cement is circulated into the annulus outside the casing string. The casing strengthens the borehole, and the cement helps to isolate areas of the wellbore during hydrocarbon production. The well may be drilled to a second designated depth, and a second string of casing or liner is run into the drilled out portion of the wellbore. The second string of casing is set at a depth such that the upper portion of the second string of casing overlaps the lower portion of the first string of casing. The second liner string is fixed or hung off the first string of casing utilizing slips to wedge against an interior surface of the first casing. The second string of casing is then cemented. The process may be repeated with additional casing strings until the well has been drilled to a target depth.
Historically, wells are drilled in an “overbalanced” condition wherein the wellbore is filled with fluid or mud in order to prevent the inflow of hydrocarbons until the well is completed. The overbalanced condition prevents blow outs and keeps the well controlled. While drilling with weighted fluid provides a safe way to operate, there are disadvantages, like the expense of the mud and the damage to formations if the column of mud becomes so heavy that the mud enters the formations adjacent the wellbore. In order to avoid these problems and to encourage the inflow of hydrocarbons into the wellbore, underbalanced or near underbalanced drilling has become popular in certain instances. Underbalanced drilling involves the formation of a wellbore in a state wherein any wellbore fluid provides a pressure lower than the natural pressure of formation fluids. In these instances, the fluid is typically a gas (e.g., nitrogen or a gasified liquid), and its purpose is to carry out cuttings or drilling chips produced by a rotating drill bit. Since underbalanced well conditions can cause a blow out, they must be drilled through some type of pressure device like a rotating drilling head at the surface of the well to permit a tubular drill string to be rotated and lowered therethrough while retaining a pressure seal around the drill string. Even in overbalanced wells there is a need to prevent blow outs. In most instances, wells are drilled through blow out preventers in case of a pressure surge.
A significant difference between conventional overbalanced drilling and underbalanced drilling is that in the latter fluid pressure in the well acts on the drill string. Consequently, when the drill string is inserted into the well or removed from the well, the drill string tends to be thrown out of the well due to fluid pressure acting on it from the bottom. As the formation and completion of an underbalanced or near underbalanced well continues, it is often necessary to insert a string of tools into the wellbore that cannot be inserted through a rotating drilling head or blow out preventer due to their shape and relatively large outer diameter. In these instances, a lubricator that consists of a tubular housing tall enough to hold the string of tools is installed in a vertical orientation at the top of a wellhead to provide a pressurizable temporary housing that avoids downhole pressures. The use of lubricators is well known in the art. By manipulating valves at the upper and lower end of the lubricator, the string of tools can be lowered into a live well while keeping the pressure within the well localized. Even a well in an overbalanced condition can benefit from the use of a lubricator when the string of tools will not fit though a blow out preventer.
While lubricators are effective in controlling pressure, some strings of tools are too long for use with a lubricator. For example, the vertical distance from a rig floor to the rig draw works is typically about ninety feet or is limited to that length of tubular string that is typically inserted into the well. If a string of tools is longer than ninety feet, there is not room between the rig floor and the draw works to accommodate a lubricator. In these instances, a down hole deployment valve or DDV can be used to create a pressurized housing for the string of tools. In general, downhole deployment valves are well known in the art, and one such valve is described in U.S. Pat. No. 6,209,663, which is incorporated by reference herein in its entirety. A downhole deployment valve (DDV) eliminates the need for any special equipment (e.g., a snubber unit or a lubricator), which is expensive and slows down the work progress, to facilitate tripping in or tripping out the drill string from the well during underbalanced drilling. Since the DDV is a downhole pressure containing device, it also enhances safety for personnel and equipment on the drilling job.
Generally, a DDV is run into a well as part of a string of casing. The DDV is initially in an open position with a flapper member in a position whereby the full bore of the casing is open to the flow of fluid and the passage of tubular strings and tools into and out of the wellbore. The valve taught in the '663 patent includes an axially moveable sleeve that interferes with and retains the flapper in the open position. Additionally, a series of slots and pins permits the valve to be openable or closable with pressure but to then remain in that position without pressure continuously applied thereto. A control line runs from the DDV to the surface of the well and is typically hydraulically controlled. With the application of fluid pressure through the control line, the DDV can be made to close so that its flapper seats in a circular seat formed in the bore of the casing and blocks the flow of fluid through the casing. In this manner, a portion of the casing above the DDV is isolated from a lower portion of the casing below the DDV.
The DDV is used to install a string of tools in a wellbore. When an operator wants to install the tool string, the DDV is closed via the control line by using hydraulic pressure to close the mechanical valve. Thereafter, with an upper portion of the wellbore isolated, a pressure in the upper portion is bled off to bring the pressure in the upper portion to a level approximately equal to one atmosphere. With the upper portion depressurized, the wellhead can be opened and the string of tools run into the upper portion from a surface of the well, typically on a string of tubulars. A rotating drilling head or other stripper like device is then sealed around the tubular string, and movement through a blowout preventer can be re-established. In order to reopen the DDV, the upper portion of the wellbore is repressurized to permit the downwardly opening flapper member to operate against the pressure therebelow. After the upper portion is pressurized to a predetermined level, the flapper can be opened and locked in place, and thus, the tool string is located in the pressurized wellbore.
In the production environment, cables (electrical, hydraulic and other types) are passed through the wellhead assembly at the surface, typically passing vertically through the top plate. Pressure seal is maintained utilizing sealing connector fittings such as NTP threads or O-ring seals. However, there does not exist a system that allows passage of the electrical power and signals through the wellhead assembly during drilling operations. A wellhead assembly that allows electrical power and signals to pass into and out of the well during drilling operations, without having to remove the valve structure above the wellhead, would provide time and cost savings. Furthermore, such wellhead assembly would provide the ability to demonstrate the performance of a tool (e.g., a DDV) through monitoring during drilling operations. Thus, there is a need for a wellhead assembly that allows electrical power and signals to pass into and out of the well during drilling operations.
Another problem encountered by many prior art downhole measurement systems is that these conventional systems lack reliable data communication to and from control units located on a surface. For example, conventional measurement while drilling (MWD) tools utilize mud pulse telemetry which works fine with incompressible drilling fluids such as a water-based or an oil-based mud; however, mud pulse telemetry does not work with gasified fluids or gases typically used in underbalanced drilling. An alternative to mud pulse telemetry is electromagnetic (EM) telemetry where communication between the MWD tool and the surface monitoring device is established via electromagnetic waves traveling through the formations surrounding the well. However, EM telemetry suffers from signal attenuation as it travels through layers of different types of formations in the earth's lithosphere. Any formation that produces more than minimal loss serves as an EM barrier. In particular, salt domes and water-bearing zones tend to completely moderate the signal. One technique employed to alleviate this problem involves running an electric wire inside the drill string from the MWD tool up to a predetermined depth from where the signal can come to the surface via EM waves. Another technique employed to alleviate this problem involves placing multiple receivers and transmitters in the drill string to provide boost to the signal at frequent intervals. However, both of these techniques have their own problems and complexities. Currently, there is no available means to cost efficiently relay signals from a point within the well to the surface through a traditional control line. Thus, there is a need for an electromagnetic communication system for two-way communication with downhole tools that addresses the limitations of EM telemetry such as the gradual decay of EM waves as the EM waves pass through the earth's lithosphere and when a salt dome or water-bearing zone is encountered.
Another communication problem associated with typical drilling systems involves the resistivity subs which contain the antennas for transmitting and receiving electromagnetic signals. Traditional resistivity subs integrated induction coils, electric circuits and antennas within the thick section of the drill collar. This method is costly to manufacture and can be difficult to service. One recently developed resistivity sub employs a separate induction coil antenna assembly fitted inside an antenna module. Each of these modules are centralized inside of the drill collar. The resistivity sub sends and receives well-bore signals via a number of antenna modules placed directly above the secondary induction coils. The sending antennas receive electrical signals from the primary induction coils and send the signals through the secondary induction coils to the wellbore. The receiving antennas do the opposite. The sending and receiving antenna modules have to be placed very close but not touching the outside surface of the primary probe where the primary induction coils are placed inside. The primary to secondary coils interface will also have to be sealed from the drilling fluid. These antenna modules must be manufactured with very tight tolerances to effectively control the primary/secondary interface gap (i.e., the distance between the primary probe and the secondary coil in the antenna module) and to seal the primary/secondary interface gap. Tight manufacturing tolerances typically results in higher costs. Thus, there is a need for an antenna module for a resistivity sub that effectively controls and seals the primary/secondary interface gap which can be manufactured with a wider range of tolerances to reduce the manufacturing costs.